The regenerative Rankine cycle has been used by the electric power industry for over 100 years. Most commonly the working fluid in these cycles is water. The regenerative Rankine cycle takes steam from a steam generator, produces shaft power by expanding the steam in a turbine, and then condenses the expanded steam in a condenser. Primary heating of the cycle's working fluid occurs in the steam generator, driven by the combustion of fossil fuel. Many modern regenerative Rankine cycles employ a reheating of the steam after an initial expansion in a High Pressure (HP) turbine. After reheating by combustion gases in a Reheater heat exchanger, integral to the steam generator, the steam is returned to the turbine cycle for further expansion in an Intermediate Pressure (IP) turbine, followed by expansion in a Low Pressure (LP) turbine; the LP turbine's exhaust is then condensed in a condenser. Note that if an IP turbine is present (accepting steam from a Reheater), its exhaust temperature is commonly higher than the HP turbine's exhaust temperature. The condensate from the condenser, or feedwater, is then routed by pumps through a series of feedwater heaters in which it is re-heated (regenerated). The heating vehicle for the feedwater is extraction steam obtained from the turbine. Feedwater heaters may be of a contact type or a closed type of heat exchanger. A closed type of heater is also termed a surface type heater; this type of heater has a shell-side and a tube-side configuration where, typically, the shell-side contains the heating fluid (extraction steam) and the tube-side contains the fluid being heated (feedwater). With a contact type of heater the extraction steam is directly mixed with feedwater, the heated feedwater/condensed steam, in a subcooled state, being pumped to the next highest pressure heater. A contact type of heater is also termed an “open” type heater. With a closed type of heater the extraction steam is contained on the shell-side of the heat exchanger, the feedwater carried within tubes. A classical text on the subject of regenerative Rankine cycles used in power plants is by J. Kenneth Salisbury, Steam Turbines and Their Cycles, Robert E. Krieger Publishing Company, Huntington, N.Y., 1950 (reprinted 1974), especially pages 43-93 and 266-273.
For feedwater heaters, feedwater is classically heated through the condensation of steam which has been extracted from the turbine, its latent heat being the principal heat transferred. Condensing heat transfer is solely dependent on the saturation temperature associated with the extracting steam, and is thus dependent on the extraction pressure delivered by the turbine. Extraction pressures are governed by the turbine's Flow Passing Ability as integrally established by the next downstream nozzle from the point of extraction. The Flow Passing Ability at any point in a steam turbine represents a reduction of Bernoulli's Equation associated with fluid passing through a nozzle (in the case of a turbine, a ring of nozzles forming the inlet to a turbine stage). When nozzles erode their flow area increases, causing, for a given mass flow, a reduction in inlet pressure and thus a reduction in the associated extraction pressure. A degradation in extraction pressure will degrade a feedwater heater's condensing heat transfer mechanism resulting in a lower feedwater temperature.
A common design practice in Europe is to supply the top heater its extraction steam from a mid-point IP turbine extraction, and to supply the next to the top feedwater heater its extraction steam from the HP turbine's exhaust. An improved balance of shell-side to tube-side differential exergies is obtained using this design, even through the second highest pressure extraction steam (from the IP turbine) is used to heat the top heater, the last feedwater heater in the cycle. The shell-side outlet of the top heater, always in a super-heated state, is then routed to a third feedwater heater where it is condensed; as is the drain flow from the second heater. With the European design, the third feedwater heater does not receive extraction steam from the turbine. Refer to FIG. 1. Therefore there are two fundamental differences in the European arrangement when compared to this invention: 1) there is no use of a plurality of condensing feedwater heaters placed in series along the feedwater path, said heaters all using the same turbine extraction steam; and 2) there is no mechanism by which the pressure of the extraction steam is increased (for the last or any feedwater heater in the system) allowing its latent heat to be removed thus minimizing extraction steam flow.
A common design practice in North America is to supply the highest pressure feedwater heater its extraction steam from the HP turbine's exhaust. This highest pressure feedwater heater is the last heater the feedwater encounters before returning to the steam generator (it is also termed the “top heater”). The second highest pressure feedwater heater is supplied extraction steam from the IP turbine. The third highest pressure feedwater heater is supplied extraction steam from the next lowest extraction pressure available from the turbine; and so forth. Refer to FIG. 3. Therefore there are two fundamental differences in the North American arrangement when compared to this invention: 1) there is no use of a plurality of condensing feedwater heaters placed in series along the feedwater path, said heaters all using the same turbine extraction steam; and 2) there is no mechanism by which the pressure of the extraction steam is increased allowing its latent heat to be removed thus minimizing extraction steam flow.
For any large steam turbine system the High Pressure (HP) turbine's exhaust pressure is controlled by the next downstream turbine's Flow Passing Ability. For a modern design, the next downstream turbine is typically the IP turbine. Thus if the nozzles associated with the first stage of an IP turbine erode, the exhaust pressure associated with the HP turbine will degrade, and will thus degrade the associated feedwater heater. In summary, the inlet area of the first nozzles of an IP turbine will control all upstream pressures: throughout the Reheater heat exchanger, the Reheater piping, and indeed the HP turbine's backpressure (the HP exhaust). When the HP turbine's exhaust is bled to the highest pressure feedwater heater and the IP inlet nozzle area has eroded, extraction pressure to this heater and thus its saturation temperature will degraded, and thus final feedwater temperature will degrade. Inlet nozzles of IP turbines erode, typically from solid particles trapped in the steam. Traditionally, and especially for the older machine, they go un-repaired for years given that full electrical generation may still be achieved using higher feedwater flows, and with ever increasing consumption of fuel and combustion air. This situation is aggravated if the power plant's over-sight authority (typically a public utility commission or public service commission) which typically allows ever higher fuel costs to be passed onto the electricity customers. However, eventually capacity issues arise from such higher flows. Examples of equipment limitations resultant from such higher flows include: limitations imposed by a combustion air fan; limitations imposed by an induce draft fan controlling combustion gas back-pressures; limitations imposed by a coal mill's capacity; limitations imposed by the capacity of feedwater pumps; limitations imposed by an auxiliary steam turbine driving a feedwater pump; and the like.
Prior art relevant to the present invention is described in U.S. Pat. No. 7,040,095 issued May 9, 2006, hereinafter '095. The inventor of '095 and the inventor of this disclosure is the same person. '095 teaches to route IP extraction steam to an Exergetic Heater, thereby heating feedwater. '095 does not employ a compressor device to increase the pressure of the IP extraction steam. The key distinction between '095 and this disclosure lies with inherent thermodynamic limitations associated with '095. '095 teachings simply do not address the situation where minimum steam flow is desired (thus minimizing lost electrical or mechanical power), while at the same time achieving a high increase in feedwater temperature. An IP turbine extraction produces steam at a lower pressure than that associated with the final feedwater. The saturation temperature associated with IP turbine extraction steam is not high enough for heating of feedwater using the extraction steam's latent heat. If the desired increase in final feedwater temperature is moderate, then using low pressure IP steam (given its very high temperature) is a viable solution as taught in '095. In essence, such use of '095 invokes a “trimming” process to the Rankine cycle. However, if the desired final feedwater temperature is high the Exergetic Heater of '095 must be designed to transfer heat from IP steam whose shell outlet temperature is higher than the desired final feedwater temperature. Obviously the Second Law can not be violated. The problem arises in that a low IP extraction pressure will not allow the latent heat to be removed thus requiring higher flow rates of IP extraction steam if a high final feedwater temperature is desired. Although '095 is a viable invention as it teaches how final feedwater temperature may be recovered, but the price of such recovery is high regards potentially high extraction steam flows and subsequent loss of turbine power.
As an example of '095 teachings, consider parameters from an actual 712 MWe coal-fired power plant. An 9.8 ΔF increase in feedwater for this unit may be achieved using 260 psiA IP turbine extraction steam at 279,695 lbm/hr flow, or 5.39% of feedwater flow. Although an additional 279,695 lbm/hr of extraction steam may appear high, it could be well viewed as a final feedwater temperature trim, justified by improved plant thermal efficiency. However, a 28.6 ΔF increase in feedwater, achieved using the same '095 Exergetic Heater, driven from the same IP extraction, will require 868,148 lbm/hr or 16.75% of feedwater flow. Such a burden on the system, especially on the Deaerator unit (DA, termed a Feedwater Tank in Europe), could easily exceed design capacity given such high flows. In addition, bear in mind this steam is derived from the IP turbine, resulting in less shaft power being developed. Improvement is required over the '095 invention.
With the preceding paragraphs in mind, the imagination must question the very nature of the regenerative Rankine cycle. Such inquiry extends far beyond the use of '095 technology and its “trimming” mechanism. What is meant is that the boundary condition of the regenerative Rankine cycle, its final feedwater temperature, is fundamentally controlled by turbine steam path pressure. Specifically, such control results form the IP turbine's flow passing ability (i.e., IP turbine's inlet pressure). In addition, as the system's power output is reduced, final feedwater temperature falls in proportion to IP inlet pressure. Why? This inherent limitation makes power plants inefficient at part loads. For fossil-fired systems this means proportionally higher green-house gas emissions per unit of output shaft power. Further still, most modern conventional power plants are designed to operate in an over-pressure main steam condition (such as 2535 psiA throttle pressure, versus a nominal 2400 psiA). Under such conditions, and of course using a higher feedwater flow, the entire turbine steam path is pressurized (i.e., with higher pressures and flows than that associated with a throttle pressure of 2400 psiA). If the steam generator is designed for the higher final feedwater temperature associated with over-pressure (typically an additional +30 ΔF in final feedwater temperature), such potential should be utilized. This utilization means that the system would employ a higher final feedwater temperature, but whose feedwater flow would be associated with a lower (routine) throttle pressure. '095 teaches no practical method of gaining such high feedwater temperature increases without major equipment modifications given its requirement for very high steam flows form the IP turbine; and, given high steam flows, high lost of turbine shaft output.
There is no known art other than '095 which has addressed the issue of degraded feedwater temperature at the operational level. IP turbine nozzle erosion will degrade the final feedwater temperature on North American steam plants, and will affect system thermal efficiency causing higher consumption of fuel. The Exergetic Heater of '095, although viable for small temperature increases, for “trimming”, will cause high extraction steam flows to be used to gain high final feedwater temperatures, and thus an unreasonable lost of shaft power. There is no known art which utilizes the higher feedwater temperature associated with a fossil-fired, over-pressure design, given the plant is nominally operated. The responsible power plant operator is in need of a solution to degraded feedwater temperature, and/or capturing the advantages of an over-pressure design, using minimum turbine extraction steam while at the same time maintaining routine feedwater flows.
There is no known design other than '095, which extracts steam from a turbine to directly heat a plurality of condensing feedwater heaters placed in series along the feedwater path. There is no known application, including '095, where a turbine's extraction steam pressure leading to a final feedwater heater, is increased such that the latent heat of the extraction steam is removed and delivered to the feedwater, thus minimizing extraction flow and achieving the desired final feedwater temperature.
It is known that a single LP turbine extraction may be designed to deliver steam to a plurality of condensing feedwater heaters, but heaters operating with the essentially same inlet feedwater conditions. These are parallel heater configurations, not series. For example, if a regenerative Rankine cycle's LP feedwater heaters contain two groups of heaters, say 5A, 6A & 7A, and 5B, 6B & 7B (where 7A & 7B are the lowest pressure heaters both receiving condensate from the condenser, 5A and 5B being the higher pressure heaters), then a single turbine extraction may supply heaters 5A and 5B, another extraction supplying heaters 6A and 6B, and another extraction supplying heaters 7A and 7B. In yet another variation, as favored by the former Westinghouse Electric Corporation, Large Steam Turbine Division, it could be that heater 5A is being supplied an extraction which is different than that which heater 5B is being supplied; i.e., asymmetric extractions. However, other than '095, there is no known design which extracts a single source of turbine steam and supplies, for example, heaters 5A and 6B, or 6B and 7B, or 7A and 5A, or heaters 5A, 6A and 7A, etc. (i.e., heaters placed in series along the feedwater path). In summary, there is no known art other than '095 which advocates using a single turbine extraction to supply a plurality of feedwater heaters placed in series along the feedwater path. However, with '095, as explained, the price of extracting to heaters placed in series is a high extraction flow given that high final feedwater temperatures are desired.
It is to be noted that '095 discusses the use of a diffuser device (another name for a simple thermocompressor), but this is taken in context of increasing the pressure of the outlet steam from an Exergetic Heater such that it may flow to a higher pressure feedwater heater; not its inlet pressure; and not such that a condensing heat transfer mechanism might take place. '095 does not disclose the use of a compressor device to increase turbine extraction pressure.
Another prior art relevant to the present invention is described in U.S. Pat. No. 4,336,105 issued Jun. 22, 1982, hereinafter '105. '105 solved a problem dealing with a Nuclear Steam Supply System (NSSS). The invention was not concerned with increasing turbine cycle efficiency per se, given a saturated (or near saturated) output from a conventional nuclear steam generator. An IP turbine extraction producing highly superheated steam was simply not available. Rather '105 was concerned about preventing freezing of liquid sodium metal at low loads on the heating side of a non-conventional nuclear steam generator; i.e., applicable to a liquid metal cooled nuclear reactor system. '105 does not employ an IP turbine extraction to heat the feedwater (an IP turbine does not exist in '105), but HP steam found at the NSSS boundary (i.e., conditions inlet to the HP turbine). '105 does not employ an additional feedwater heater given that the invention employs HP (boundary) steam as delivered to a high pressure heater ('105 FIG. 1, item 44). Indeed, all feedwater heaters considered ('105 FIG. 1, items 40, 42 and 44), are prior art; i.e., in-situ equipment. Col. 2, Lines 55-57 of '105 discusses the operational mechanics of controlling the final feedwater temperature—relating extraction pressure to final feedwater temperature. However, such discussion in '105 is in the context of a solution for low load operation by manipulating the NSSS's Moisture Separator Reheater (MSR) pressures and flows such that proper feedwater heating could be achieved (see Col. 3, Lines 1-22 in '105), and thus to prevent freezing of the liquid sodium coolant.
Another prior art relevant to the present invention is described in U.S. Pat. No. 3,238,729 issued Mar. 8, 1966, hereinafter '729. This patent describes the use of a thermocompressor used to increase the pressure of a non-top heater; a device in which the final feedwater temperature is not altered. The '729 invention does not teach how the final feedwater temperature may be increased; this is not an objective of the invention. '729 FIG. 1 describes how a single turbine extraction supplies two feedwater heaters placed in series, but note that said heaters, features 31 and 29 in FIG. 1 of '729, are both non-condensing. Col. 3, Lines 13-17 of '729 states clearly that the steam associated with feature 31 is “ . . . for the most part only fully or partly desuperheated and then passes on to the heater 27, in which it is condensed.” The invention '729 clearly is a fore-runner to the modern European design discussed above.
Another prior art relevant to the present invention is described in European Patent 0 851 971 issued Sep. 4, 1996. This patent describes the use of thermocompressors to increase the pressure of extracted steam. No mention is made of increasing final feedwater temperature, unit thermal efficiency is not improved.
Another prior art relevant to the present invention is described in European Patent 0 773 348 issued May 14, 1997. This patent describes a low pressure turbine's extraction system in which the condensate's temperature is increased. Again, no mention is made of increasing final feedwater temperature, unit thermal efficiency is not improved.
Another prior art relevant to the present invention is described in U.S. Pat. No. 3,973,402 issued Aug. 10, 1976, hereinafter '402. This invention employs a “pressure-increasing ejector element” (i.e., a thermocompressor as used herein) to increase the extraction pressure of a top feedwater heater. '402 is applicable solely to a Nuclear Steam Supply System (NSSS). '402 does not employ IP turbine extraction steam but HP extraction steam as supply steam to the thermocompressor; motive steam is obtained as subcooled condensate from the NSSS's Moisture Separator Reheater (MSR). There is no description of a single turbine extraction feeding a plurality of condensing feedwater heaters placed in series.
There is a need to improve the thermal efficiency of a fossil-fired power plant which employs a Reheater, by increasing its final feedwater temperature. The need to increase final feedwater temperature may arise due to eroded IP turbine nozzles, a degraded top feedwater heater, a desired to improve thermal efficiency beyond design, and/or a desire to divorce final feedwater temperature from the inherent limitations of the regenerative Rankine cycle. Such improvement should minimize losses to turbine shaft power (e.g., electric generation). Such improvement should be design to increase thermal efficiency and thus to reduce the carbon footprint of the fossil-fired power plant.